Compositions and methods for treating a subterranean formation

ABSTRACT

A method is provided for diverting the majority of the fluid injected into a stratified subterranean formation, that has at least one problematic zone and at least one hydrocarbon zone, into the hydrocarbon zone. In the method, a viscous diverting fluid made with a gelling amount of a surfactant and an acid is injected before the main treatment; after the treatment the acid decomposes the surfactant. The main treatment may be hydraulic fracturing, acid fracturing and matrix acidizing. The fluid used as the diverting fluid may also be used as the carrier fluid in hydraulic fracturing or gravel packing. Destruction of the surfactant alleviates the potential of diverters or carrier fluids to damage formations.

REFERENCE TO RELATED APPLICATION

This application is a continuation of U.S. application Ser. No.10/191,179, filed Jul. 9, 2002, now U.S. Pat. No. 6,929,070, whichclaims the benefit of U.S. Provisional Application No. 60/343,145, filedDec. 21, 2001.

FIELD OF THE INVENTION

This invention relates to treatment of subterranean formationspenetrated by wellbores. In particular, it relates to stimulationtreatments such as fracturing, matrix acidizing and acid fracturing, ofstratified formations having one or more layers that are problematic butoil-containing and one or more layers that are more permeable to oil orwater than the problematic zone or zones. Most particularly it relatesto compositions and methods for maximizing the amount of the treatmentfluid that is injected into the problematic zones rather than into themore-permeable zones.

BACKGROUND OF THE INVENTION

In a wide variety of oilfield treatments, in which treatment fluids areinjected into a formation through a wellbore, the formation beingtreated is stratified. Typically in such stratified formations, thepermeabilities of the strata differ, sometimes substantially. Also,typically, one or more of the strata (which for simplicity we will callthe oil-containing zone), will contain potentially produciblehydrocarbon (oil, condensate, or gas). In this discussion we use theterms “oil-containing” and “hydrocarbon-containing” interchangeably andwe use the terms “oil” and “hydrocarbon” interchangeably. Often one ormore other strata (which for simplicity we will call thewater-containing zone), will contain in its pores entirely, or almostentirely, only formation water or brine and will contain either nohydrocarbon or only residual hydrocarbon remaining after the produciblehydrocarbon has already been produced from that zone. This zone will bea good producer of fluid that is all or mostly water. The other zone orzones will be considered problematic because they contain hydrocarbonthat is not being produced properly. The zones that are producing fluid,either water or hydrocarbon or both, will be termed “non-problematic”here, even though water production is normally undesirable. Bydefinition, here, the “problem” is that a zone is not producing or notproducing satisfactorily, so by this definition a zone that is producingis “non-problematic”. If both oil and water phases are present in azone, but some or all of the producible oil has been produced, the zonewill be considered a water-containing zone; in this case water istypically the continuous phase, and the flowing phase, and the watersaturation is high. (However, if the formation is oil-wet, oil could bea thin continuous phase on the pore surfaces but water would still bethe flowing phase.) Frequently, it is also true that the permeability toinjected fluid of the water-containing zone is greater than thepermeability to injected fluid of the oil-containing zone.

In other cases, there is no water-containing zone, but there ispermeability stratification of the hydrocarbon-containing zones orstrata. In such cases, oil will be produced preferentially from the morepermeable zones, termed “non-problematic”. The less permeable zone orzones will be considered problematic because again they containhydrocarbon that is not being produced properly. They could beproblematic because they are inherently less permeable (because of thegeology) or because they have been damaged.

In many oilfield treatments, it is desirable to inject all or most ofthe injected fluid into one or more specific “problematic”oil-containing zones, i. e. stratum or strata that contain potentiallyproducible hydrocarbon that is not or will not be satisfactorilyproduced, and not into other zones. These zones are “problematic”because they are oil-containing but are not or will not satisfactorilyproduce the hydrocarbon that they contain. In the situations underconsideration here, production from these problematic zones isunsatisfactory because there are more-productive (“non-problematic”)zones. These more productive zones may be water-containing zones thatproduce water. On the other hand, there may not be water zones, but theproblematic zones may inherently have lower permeabilities than theother zones or may have been damaged in a drilling, completion orproduction process, so that some oil-containing zones can or willproduce oil and others can or will not. For example, in hydraulicfracturing (including acid fracturing) an optimal treatment would placethe fracture entirely in the problematic zone(s). Similarly, inacidizing treatments (of sandstone formations to remove damage, or ofcarbonate formations to create flow paths such as wormholes) an optimaltreatment would be one in which all the injected fluid was placed in theproblematic zone. These requirements are important because the objectsof such treatments are to increase the permeability or the volume (orboth) of the flow path for fluids in the problematic zone while notcreating such increases in water-containing zones, or, if there are nowater-containing zones, creating greater increases in the “problematic”zones than in the other zones. Furthermore, treatment fluid injectedinto a water-containing zone is at best “wasted” (and that zone is oftenthus called a “thief” zone) even if it does not enhance the flow paththere. Worse, treatment fluid injected into a water-containing zonecould increase water production. In practice, treatments often do not goprimarily into the problematic zones.

In most of the following discussions, the “problematic” zones will bedescribed as though they were problematic relative to water-containingzones, but it should be appreciated that problematic zones may beproblematic relative to oil-containing zones. The zones into which it isdesired to inject treatment fluids will normally be described as“oil-containing” zones even though in some cases all the zones,including the thief zones, are oil-containing. Typically, undivertedtreatments enter thief zones having high water saturation (because thetreatments are aqueous) and/or high permeability (because fluids followthe path(s) of least resistance). Methods devised to increase injectioninto the problematic oil-containing zone, even if it has lowerpermeability, are called diversion methods, and mechanical devices orchemicals used in them are called diverters. Only chemical diverterswill be considered further here.

Some of the simple chemical diverting agents that have been used in thepast include oil-soluble resins, water-soluble rock salt, and emulsions.A chemical diverter based on aqueous micellar viscoelastic surfactantgels was described in U.S. Pat. No. 5,979,557 which has a commonassignee as the present application. This material will be called “VESDiverter”. VES Diverter is used primarily in acidizing and fracturing;its use in acid diversion is described in Chang, et al, “Case Study of aNovel Acid-Diversion Technique in Carbonate Reservoirs,” SPE paper 56529(February, 1998). It can be used in both sandstones and carbonates. Thesurfactants described in U.S. Pat. No. 5,979,557 are amines, amine saltsand quaternary amine salts, preferably erucyl bis(2-hydroxyethyl)methylammonium chloride, also known asN-cis-13-docosenoic-N,N-bis(2-hydroxyethyl)-N-methyl ammonium chloride.A salt (for example an inorganic salt of Ca, Mg, Zn, Al, or Zr) must beincluded in the fluid for the fluid to gel; VES Diverter may alsoinclude an optional water-soluble organic salt and/or alcohol to improveviscoelasticity under severe conditions. Diversion with VES Diverter maybe temporary or permanent. The micelles are broken by dilution byformation water or by contact with hydrocarbons, but the surfactantmolecules remain intact. Some surfactants sometimes cause emulsions whenthey contact certain oils; if this occurs in fracturing or in carbonatesit is unlikely to cause damage if the carbonate acidizing left largewormholes and if the fracturing left large flow paths; flow throughthese is unlikely to be impeded by the presence of emulsions. However,emulsions could impede flow through the smaller flow paths remainingafter sandstone acidizing, or if small fractures or small wormholes werecreated.

It is also known to use self-diverting acids, typically consisting ofhydrochloric acid mixed with a polymeric gelling agent and apH-sensitive cross-linker, in matrix acidizing. Self-diverting acids aretypically designed to gel at intermediate pH values, when the acid ispartially spent. Self-diverting systems that are not based oncross-linked polymers but which rely upon viscoelastic surfactants aredescribed in U.S. Pat. No. 4,695,389 (see also, U.S. Pat. No. 4,324,669,and British Patent No. 2,012,837, both cited there)—which has a commonassignee as the present application. Viscoelastic surfactants basedsystems exhibit very low friction pressure and therefore are easy topump and yet, form a gel downhole. U.S. Pat. No. 4,695,389 discloses aviscoelastic surfactant-based gelling agent intended for use in acidfracturing. The particularly preferred embodiment is a fluid comprisedof N,N-bis(2-hydroxyethyl) fatty amine acetic acid salt (the gellingagent), an alkali metal acetate salt, acetic acid (the acid—whichactually removes the damage from the formation), and water.

Another chemical diverter system based on VES technology has beendescribed in U.S. Pat. No. 6,399,546 which has a common assignee as thepresent application. This material, called a “Viscoelastic DivertingAcid” (VDA), is typically made from surfactants made from betaines,which we will call BET surfactants, and others, that are described inU.S. Pat. No. 6,258,859. VDA fluids are used for diversion in acidizingor acid fracturing treatments. VDA fluids are made from mixtures ofstrong acids, such as HCl, and BET surfactants. These materials areungelled when strongly acidic as pumped, but as the acid “spends” or isconsumed, and the pH rises and the electrolyte content of the fluidincreases (typically by introduction of calcium ions as a consequence ofthe dissolution of carbonates) the fluids gel. Thus, when first injectedthey enter the most permeable zone(s), but when they gel they block thatzone and divert subsequently injected fluid into previouslyless-permeable zones.

Other improved self-diverting systems have been described in U.S. Pat.No. 6,399,546, having a common assignee as the present application, andits corresponding International Patent Application WO 01/29369. Thisapplication, hereby incorporated by reference, provides formulations,suitable for acid treatments, comprising an amphoteric surfactant thatgels as the acid spends in the presence of an activating amount of aco-surfactant and of multivalent cations typically generated by the acidreaction with the formation. When the gelling agent is mixed inhydrochloric acid, the co-surfactant prevents the gelling of thesolution; the solution gels when the pH increases above about 2.

GB Patent Application No. GB 0103449.5, assigned to the same assignee asthe present application, describes cleavable surfactants containingchemical bonds such as acetals, amides or esters that can be broken byadjusting the pH. Examples show some that are broken by very diluteacetic acid (0.5 to 1%) at temperatures below about 60° C. and some thatcan be broken when the pH is raised above about 8. That applicationstates that cleavable surfactants are useful in wellbore service fluids,especially fracturing fluids and well clean-out fluids.

Methods have been developed that would destroy the micellar structure ofsome VES fluids if they were being used as diverters. U.S. PatentApplication Publication No. US 2002/0004464 A1, which has a commonassignee as the present application, teaches that certain carboxylicacids, that have charges opposite to the VES's head group can act asbreakers by destroying the micellar structure of the VES fluid. It alsoteaches that some organic acids, such as adipic, citric, or glutaricacids, in the protonated form can act as breakers. On the other hand,for certain surfactants, organic acid salts such as salicylates can bestabilizers. That application teaches that whether or not an organicacid acts as a VES breaker depends upon whether the surfactant isanionic, cationic, zwitterionic or nonionic. It focuses on breakers forviscoelastic surfactant systems based upon cationic surfactants such aserucyl methyl bis(2-hydroxyethyl) ammonium chloride and zwitterionicsurfactants such as betaine surfactants and teaches only breakers thatfunction by destroying the micellar structure of the VES fluid.

Often, diversion methods either cause damage by leaving behindparticles, polymer, sludge, precipitates, surfactants, etc. and/or areexpensive and complicated and/or require specialized equipment andfacilities (for example to generate, monitor and control foams). Also,many chemical diverters cannot be used at high temperatures or areincompatible with some chemicals (such as strong acids or very low orvery high salt concentrations). There exists a need for simplecompositions and methods for diversion of injected fluids, especiallyacidic fluids, at high temperatures, in which the diverters arecompletely broken at predetermined times or conditions after the maintreatment is completed. There is also a need for chemical divertersystems that after degradation do not leave behind decompositionproducts that are surfactants, polymers or crosslinked polymerfragments.

SUMMARY OF THE INVENTION

In one embodiment, before a well treatment of a stratified subterraneanformation that is made up of at least one water-containing zone and atleast one hydrocarbon-containing zone (which is not producing or notproducing satisfactorily and so is called “problematic”), a divertingfluid is injected into the water-containing zone (which is producing andso is termed “non-problematic”). This procedure, which divertssubsequently-injected fluids in the well treatment into thehydrocarbon-containing zone is accomplished by injecting a divertingfluid that consists of at least an aqueous viscous gelled fluid made upof water, a gelling amount of a surfactant, and an acid. This divertingfluid preferentially enters the water-containing zone, and the aciddecomposes the surfactant after the well treatment. In anotherembodiment, before a well treatment of a stratified subterraneanformation that is made up of at least one hydrocarbon-containing zonethat produces or can produce hydrocarbon (and so is termed“non-problematic”) and at least one hydrocarbon-containing zone thatdoes not or will not produce hydrocarbon satisfactorily (called a“problematic” zone), because for example it has inherently lowerpermeability or has been damaged during drilling, completion, orproduction, a diverting fluid is injected into thehydrocarbon-containing zone that produces hydrocarbon. This procedure,which diverts subsequently-injected fluids in the well treatment intothe problematic hydrocarbon-containing zone is accomplished by injectinga diverting fluid that consists of at least an aqueous viscous gelledfluid made up of water, a gelling amount of a surfactant, and an acid.This diverting fluid preferentially enters the zone that produces (the“non-problematic” zone), and the acid decomposes the surfactant afterthe well treatment. This diverting fluid is a viscous high-temperatureacid-degradable aqueous gel. In other embodiments, the surfactantdecomposition mechanism is acid hydrolysis, the diverting fluid issubstantially salt free, and the formation temperature exceeds 37° C.

In another embodiment, the surfactant has the following amide structure:

in which R₁ is a hydrocarbyl group that may be branched or straightchained, aromatic, aliphatic or olefinic and has from about 14 to about26 carbon atoms and may contain an amine; R₂ is hydrogen or an alkylgroup having from 1 to about 4 carbon atoms; R₃ is a hydrocarbyl grouphaving from 1 to about 5 carbon atoms; and Y is an electron withdrawinggroup. Preferably the electronic withdrawing group is a quaternary amineor an amine oxide. More preferably it is a betaine having the structure:

in which R is a hydrocarbyl group that may be branched or straightchained, aromatic, aliphatic or olefinic and has from about 14 to about26 carbon atoms and may contain an amine; n=about 2 to about 4; and p=1to about 5, and mixtures of these compounds. Most preferably thesurfactant is the betaine in which R is C₁₇H₃₃ or C₂₁H₄₁, and n=3 andp=1.

In other embodiments, the viscous high-temperature acid-degradableaqueous gels may contain one or more of at least a cosurfactant, analcohol, a chelating agent, and an iron control agent. In yet anotherembodiment, when the non-problematic zone contains at least a residualamount of hydrocarbon, the method further includes injecting a mutualsolvent prior to injecting the diverter fluid. The mutual solvent ispreferably a low molecular weight ester, alcohol or ether; mostpreferably it is ethylene glycol monobutyl ether. The mutual solvent maybe mixed with other materials such as water or diesel.

In yet other embodiments, the well treatment following the divertingstep is hydraulic fracturing, acid fracturing, matrix acidizing, ormatrix dissolution with a chelating agent.

In yet further embodiments, the fluid used in at least part of a gravelpacking, hydraulic fracturing, acid fracturing, matrix acidizing, ormatrix dissolution with a chelating agent treatment is the same fluidthat is described above as a viscous high-temperature acid-degradableaqueous gel.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows the initial viscosity of a viscous high-temperatureacid-degradable aqueous gel comprising 7.5% as-received BET-E-40, 5% KCland 2% HCl vs. temperature.

FIG. 2 shows the initial viscosity of viscous high-temperatureacid-degradable aqueous gels comprising 7.5% as-received BET-E-40 vs.HCl concentration at about 23° C.

FIG. 3 shows the time at 88° C. for the viscosity of high-temperatureacid-degradable aqueous gels comprising 7.5% as-received BET-E-40 havingdifferent acid concentrations to fall below about 50 cP at 170 sec⁻¹.

FIG. 4 shows the decrease in viscosity measured at 170 sec⁻¹ vs. time at88° C. for high-temperature acid-degradable aqueous gels comprising 7.5%as-received BET-E-40 and differing acid concentrations.

DETAILED DESCRIPTION OF THE INVENTION

We have identified a class of surfactants that has very valuableproperties. In aqueous solutions these materials form viscous gels thatare stable at high temperatures with or without added salts,cosurfactants, alcohols or chelating agents. Most importantly, thesesurfactants can form the gels in strong mineral acids and the acidconcentration can be adjusted so that the gels are stable under oilfieldtreatment conditions just long enough to survive during the oilfieldtreatment and to act as chemical diverters during that treatment andthen they decompose by the action of the acid to destroy the gelstructure while not forming damaging decomposition products. The aqueousviscous high-temperature acid-degradable gels formed by thesesurfactants under these conditions can also be used as the main fluidsin certain oilfield treatments, as will be described further later.

Key points are that these compounds can form gels that are difficult tohydrolyze even in strong acids and that they can provide diversion undersalt free conditions. By “difficult to hydrolyze” we mean thathydrolysis at a given temperature and pH takes more than at least onehour longer than the oilfield treatment, as determined by reduction ofthe viscosity of the fluid to less than 50 cP at a shear rate of 100sec⁻¹. By “diversion” of a fluid we mean that more of the fluid entersthe hydrocarbon-zone(s) than would be expected from a simple calculationbased on the relative permeabilities to the treatment fluid of thedifferent strata. By “salt free” we mean that no salts, such as thosecommonly added to oilfield treatment fluids for the purposes of claystabilization, VES formation, or density elevation, (such as but notlimited to alkali metal, alkaline earth metal, ammonium ortetramethylammonium halides or formates) have been added in amountsnormally necessary to achieve those or similar objectives. We do notmean that the only electrolytes are mineral acids.

Many surfactants are known to form viscous gels in aqueous solutions,although they usually require added salts and/or cosurfactants for thegels to be sufficiently viscous and stable to be useful under oilfieldtreatment conditions. Such gels and their uses are described, forinstance in U.S. Pat. Nos. 6,306,800; 6,035,936; and 5,979,557. Theaspect of the structure of the surfactants that are discussed here thatmakes these surfactants useful in the present invention is that theyhave chemical linkages, in particular amide linkages that are stabilizedby nearby chemical functional groups. In particular, these surfactantshave cationic or electron-withdrawing groups within about 2 atoms of thenitrogen. The first step in acid hydrolysis of amides is protonation ofthe amide functionality. The nearby electron withdrawing group inhibitsthis protonation and greatly slows the acid hydrolysis, whereas othersurfactants that do not have this aspect to their structure are eithertoo stable or too unstable in strong acids to be useful.

Several zwitterionic surfactants that have been found to be particularlyuseful in forming aqueous viscous high-temperature acid-degradable gelsin any electrolyte concentration; these materials will form gels with noadded salt or even in heavy brines. Two preferred examples are betainescalled, respectively, BET-O and BET-E. The surfactant in BET-O-30 isshown below. It is designated BET-O-30 because as obtained from thesupplier (Rhodia, Inc. Cranbury, N.J., U.S.A.) it is called MirataineBET-O-30 because it contains an oleyl acid ester group (including aC₁₇H₃₃ tail group) and contains about 30% active surfactant; theremainder is substantially water, a small amount of sodium chloride, andisopropanol. An analogous material, BET-E-40, is also available fromRhodia and contains a erucic acid ester group (including a C₂₁H₄₁ tailgroup) and is 40% active ingredient, with the remainder againsubstantially water, a small amount of sodium chloride, and isopropanol.Below, these surfactants will be referred to as BET-O and BET-E (andgenerically as “BET surfactants”); in the examples, BET-O-30 andBET-E-40 were always used. The surfactants are supplied in this form,with an alcohol and a glycol, to aid in solubilizing the surfactant inwater at these high concentrations, and to maintain it as a homogeneousfluid at low temperatures. In field use, after dilution, the amounts ofthe other components of the as-received materials are insignificant. BETsurfactants, and others, are described in U.S. Pat. No. 6,258,859.According to that patent, cosurfactants may be useful in extending thebrine tolerance, and to increase the gel strength and to reduce theshear sensitivity of the VES-fluid, especially for BET-O. An example issodium dodecylbenzene sulfonate (SDBS). Betaines will gel aqueoussolutions without the need for added salts, as is necessary for manyother surfactants that form VES fluids.

Aqueous gelled systems based on BET-E decompose in about 4 to about 10%HCl at temperatures greater than or equal to about 93° C. in relativelyshort times (for example about 40 minutes to about 2 hours) bydecomposition of the surfactant. This system maintains viscosity athigher temperatures than VES Diverter and then decomposes more rapidly.The stability of the surfactant (the time it takes for the surfactant todecompose at a given temperature) can be controlled by adjusting theacid concentration.

The methods and fluids of the invention can be used for chemicaldiversion before many oilfield treatments, for example, but not limitedto matrix acidizing, matrix dissolution with chelating agents, acidfracturing (either as the aqueous gelled acid proppant laden fluid or asthe pad), gravel packing, wellbore cleanout, or conventional (non-acid)fracturing (again either as the aqueous gelled proppant laden fluid oras the pad).

Viscous aqueous high-temperature acid-degradable gels made with thesesurfactants are particularly useful as diverters in hydraulic fracturingand in acidizing treatments (both acid fracturing and matrix acidizing).By “hydraulic fracturing” we mean a stimulation treatment routinelyperformed on oil and gas wells in low-permeability reservoirs, usuallysandstone reservoirs. Specially engineered fluids are pumped at highpressure and rate into the reservoir interval to be treated, causing avertical fracture to open. The wings of the fracture extend away fromthe wellbore in opposing directions according to the natural stresseswithin the formation. Proppant, such as grains of sand of a particularsize, is mixed with the treatment fluid keep the fracture open when thetreatment is complete. Hydraulic fracturing creates high-conductivitycommunication with a large area of formation and bypasses any damagethat may exist in the near-wellbore area. By “acid fracturing” we meanfracturing treatments in which acid is introduced into the fracture;this is done in carbonate reservoirs. The acid can dissolve at leastpart of the rock; irregular etching of the fracture face and removal ofsome of the mineral matter result in the fracture not completely closingwhen the pumping is stopped, and the creation of flow channels. In acidfracturing, it is common to pump sequential stages of viscous fluids (toinitiate fracture formation or to enhance fracture growth) and of acids.In theory, in such cases the acid fingers into the viscous fluid. Theseacid fingers etch away the carbonate formation only where the formationis exposed to an acid finger. By “matrix acidizing” we mean thetreatment of a reservoir formation with a stimulation fluid containing areactive acid. In sandstone formations, the acid reacts with the solublesubstances in the formation matrix (such as carbonates from drilling orcompletion fluids that have invaded the matrix) to clean out or enlargethe pore spaces. In carbonate formations, the acid dissolves virtuallythe entire formation matrix with which it comes in contact. In eachcase, the matrix acidizing treatment improves the formation permeabilityto enable enhanced production of reservoir fluids. Matrix acidizingoperations are ideally performed at high rate, but at treatmentpressures below the fracture pressure of the formation. This enables theacid to penetrate the formation and extend the depth of treatment whileavoiding damage to the reservoir formation.

By “sandstone” we mean a clastic sedimentary rock whose grains arepredominantly sand-sized. The term is commonly used to implyconsolidated sand or a rock made of predominantly quartz sand, althoughsandstones often contain feldspar, rock fragments, mica and numerousadditional mineral grains, held together with silica or another type ofcement. Sandstone formations may contain small amounts of carbonates. By“carbonate” we mean a class of sedimentary rock whose chief mineralconstituents (typically 95% or more) are calcite (limestone) andaragonite (both CaCO₃) and dolomite [CaMg(CO₃)₂], a mineral that canreplace calcite during the process of dolomitization. Carbonateformations can contain small amounts of sandstone.

In such treatments (which we will call “main” treatments to distinguishthem from the diversion step) in addition to diversion, the viscoushigh-temperature acid-degradable gel fluids maximize the flowback rateof hydrocarbons after the treatments, maximize cleanup (removal ofharmful components of the diverters or of the main treatment fluids),and simultaneously minimizing water production. It is recommended thatthe diversion be carried out so that the chemical diverter of theinvention penetrates to a radial distance of at least 10% of the depthof invasion of the main treatment. We will call the fluid used in themain treatment the carrier fluid if the main treatment is hydraulicfracturing or gravel packing. By “carrier fluid” we mean a fluid that isused to transport materials into or out of the wellbore. Carrier fluidsideally have the ability to efficiently transport the necessary material(such as pack sand during a gravel pack), the ability to separate orrelease the materials at the correct time or place, and compatibilitywith other wellbore fluids while being nondamaging to exposedformations. If the main treatment is acid fracturing or acidizing, wewill call the fluid used in the main treatment the “main” acid fluid.

When used in hydraulic fracturing the viscous high-temperatureacid-degradable gels can be used before the pad (purely as a diverterbelow fracture pressure), in the pad, or in the fracturing fluid (thecarrier fluid). (By “pad” we mean a fluid, that is used to initiatehydraulic fracturing, that does not contain proppant, or a fluid, thatis used to initiate acid fracturing, that may not contain acid. Pads maybe, and often are, viscosified.) Optionally, the viscoushigh-temperature acid-degradable gels may include a cosurfactant toincrease viscosity or to minimize the formation of stable emulsions thatcontain components of crude oil. In hydraulic fracturing, in addition todiversion, limiting the inflow of formation water during and after awell turn around to maximize recovery of fracturing fluid and componentsthereof after a hydraulic fracturing treatment of a formation having ahydrocarbon zone and a water-bearing zone is particularly important.

In hydraulic fracturing the viscous high-temperature acid-degradableaqueous gel used as a chemical diverter is pumped into the formation.This fluid would have a viscosity in excess of 10 cp, and preferably atleast 35 cp, e.g., from about 35 cp to about 500 cp, and more preferablyat least 50 cp at 100 sec⁻¹ at bottom hole temperature. Since the fluidis water based, the mobility of the viscosifying surfactant into thepores of the water-bearing zone is greater than the mobility of theviscosifying surfactant into the oil or gas zone. In addition, theviscous surfactant system retains its viscosity on exposure to formationwater but loses its viscosity on exposure to hydrocarbons. As a result,a plug of viscous fluid is placed selectively in the pore structure ofwater-containing zone(s), but not in the pore structure of thehydrocarbon-containing zone(s). Thereafter, the fracturing treatment isperformed. When the fracturing treatment is turned around, theproduction of formation water is selectively retarded by this plug ofviscous fluid, thus increasing the amount of fracturing fluid producedand in turn improving the fracture clean-up and maximizing thesubsequent flow path for production of hydrocarbons. In an idealtreatment, no gel would enter the oil-containing zone and the gel in thewater-containing zone would be permanent. In actuality, however, somegel may enter the oil-containing zone, and even if it does not, thensome surfactant-containing fluid will. The acid degradation of thesurfactant ensures that any blockage of the oil-containing zone, by gelor by an emulsion that might be formed by produced oil plus surfactant,will be eliminated. The acid also may remove near wellbore damage andfurther ensure flow continuity between the fracture and the wellbore.Even though the acid-degradation of the surfactant may also result inincreased flow from the water-containing zone, the benefits obtained bythe effects in the oil-containing zone will be more important.

It was stated above that the viscous surfactant system retains itsviscosity on exposure to formation water but loses its viscosity onexposure to hydrocarbons. This is because the micellar system structureis destroyed very quickly by contact with only a small amount ofhydrocarbon. However, although some VES gel micellar system structuresare destroyed relatively rapidly by contact with formation water orother aqueous fluids, the viscous high-temperature acid-degradableaqueous gels of the present invention are not. This is because theeasily destroyed VES systems are made with surfactants that form gelsover only a narrow range of salt concentrations; influx of water dilutesthe system and reduces the salt concentration to below that which isnecessary to form gels. (Or, in some cases of very high-brine formationwaters, increases the salt concentration above that at which thesurfactant can gel.) However, the surfactants of the present system formgels over a very broad range of salinity, so dilution by formation wateror other aqueous fluids does not break the micellar structure of thegels, unless the surfactant itself is diluted below the concentration atwhich it can form the micellar structure.

The preferred sequence of injection of fluids in sandstone acidizing ismutual solvent, then an optional brine spacer, then the viscoushigh-temperature acid-degradable gel, then an optional HCl preflush,then a HCl/HF main acid fluid, then a post flush. For carbonate, thepreferred sequence is a mutual solvent, that may be mixed for examplewith diesel or water, then an optional brine spacer, then the viscoushigh-temperature acid-degradable gel, then HCl as the main acid fluid,then a post flush. (The viscous high-temperature acid-degradable gel maynot always be optimally useful in carbonate formations because it couldbe difficult in the presence of carbonate to maintain a high enough HClconcentration for the hydrolysis of the surfactant to occur. Use couldbe limited to special situations where high acid concentrations—orvolumes—and limited exposure to carbonate—in terms of time or surfacearea—are designed into the treatment so that enough acid remains todegrade the gel.) In either case, the HCl or HCl/HF may be used withorganic acids such as acetic acid or formic acid. Mutual solvent, suchas 10% ethylene glycol monobutyl ether, is used as the post flush tostrip any oil wetting surfactant from the surface and leave it waterwet. In sandstone, the HCl preflush is commonly a 5 to 15% HCl solutioncontaining a corrosion inhibitor. It displaces Na⁺ and K⁺ and dissolvescalcite (calcium carbonate). This prevents subsequent precipitation ofsodium or potassium fluosilicates or calcium fluoride when HF isintroduced, and saves more-expensive HF. The post flush (for oil wells ahydrocarbon like diesel, or 15% HCl; for gas wells, acid or a gas likenitrogen or natural gas) also isolates the reacted HF from brine thatmay be used to flush the tubing, as well as restoring a water-wetcondition to the formation and to any precipitates that did form. If thepost flush is a gas, the cleanup additives are put in the last HCl/HFstage. For either sandstone or carbonate acidizing, the sequence ofstages may be repeated. In either case, the pre flush and/or post flushalso help to minimize any incompatibilities between chemical diverters,treatment fluids, and oil. In matrix acidizing the goal is usually tocreate dominant wormholes that penetrate through the near-wellboredamaged area. For acidizing, the viscous high-temperatureacid-degradable gel selectively blocks the pore structure in thewater-bearing zone but does not block the pore structure of thehydrocarbon zone at the formation face and thus diverts the acid awayfrom the water-bearing zone and into the hydrocarbon zone.

For acidizing, the viscous high-temperature acid-degradable gels of thepresent invention have a great advantage over other gelled fluids,including other gelled VES fluids, because they do not require salts forgelation. As has been noted, acidizing systems for sandstone acidizinginclude HF or an HF precursor. Fluoride ion precipitates in the presenceof multivalent and even most monovalent metal cations. Therefore,diverter systems that require metal salts to gel (or rock salt used as adiverter) cannot be allowed to contact acids that contain fluoride. Whenusing such diverters, spacers such as solutions of HCl, mutual solvent,acetic acid, or salts with organic cations such as ammonium chloridemust be used to prevent contact between the diverter and theHF-containing treatment fluid. The aqueous viscous high-temperatureacid-degradable gels of the present invention are excellent divertingagents for fluids containing HF or HF precursors because they can beformed using mineral acids, such as HCl, as the only electrolyte (thusno metal salts) so that precipitation of fluorides is reduced.Generation of cations from dissolution of the formation rock can becontrolled by addition of appropriate sequestering or chelating agents.In fact, HF can be included in the aqueous gel compositions of thepresent invention.

The viscous high-temperature acid-degradable aqueous gels of the presentinvention can also be used as diverters for matrix dissolution bychelating agents, a treatment analogous to matrix acidizing. In matrixdissolution by chelating agents, fluids containing high concentrationsof such chelating agents as ethylenediaminetetraacetic acid,hydroxyethylethylenediaminetriacetic acid or hydroxyethyliminodiaceticacid or their various salts, or mixtures of these acids and/or theirsalts, are injected into a carbonate matrix in order to dissolve aportion of the matrix, or are injected into a sandstone matrix todissolve carbonate damage. These treatments can be performed over a verybroad pH range, from about 2 to about 10. Commonly, the chelating agentsor their salts are present in the treatment fluid at their uppersolubility limit for the pH used. One preferred method of matrixdissolution by chelating agents is the use of such chelating agents inthe presence of strong mineral acids such as HCl. Matrix dissolution bychelating agents is to be distinguished from other oilfield stimulationtreatments, such as fracturing or acidizing, in which much smalleramounts of these chelating agents may be present as stabilizers or metalcontrol agents.

VES Diverter requires an organic or inorganic salt to generate adequateviscosity. With too little salt, the system will not gel; too much saltacts as a breaker, although it is possible to stabilize some systems inhigh brine. Although the viscous high-temperature acid-degradable gel ofthe present invention can be made with no added salts, we have foundthat BET-O gels can be stabilized, even in brines containing up to atleast about 80% CaCl₂ or about 160% CaBr₂, up to temperatures of about135° C., by the addition of either a co-surfactant (such as sodiumdodecyl benzene sulfonate) or a chelating agent (such ashydroxyethylethylenediaminetriacetic acid (HEDTA) orhydroxyethyliminodiacetic acid (HEIDA)) but not both. BET-E gels arestable to similar high brines even without stabilizers. Therefore, theviscous high-temperature acid-degradable gels are stable in acidizingand acid fracturing applications even when they are initially made saltfree but the Ca⁺⁺ concentrations rise very high due to the dissolutionof carbonates by the acid.

The VDA chemical diverter method based on VES technology is described inU.S. Pat. No. 6,399,546. The method uses BET surfactants with aco-surfactant (like the weak organic acid SDBS) and a very strong acid.This system is used as the main acid fluid in acid treatments. As longas the acid concentration, for example HCl, remains above a certainlevel, for example about 3% for one of the systems described in thatpatent, the system is a low viscosity fluid without an elongatedmicellar structure. As the acid reacts with carbonate and is consumed,the system gels. This is because in sufficiently high concentration HCl,protonated (cationic) amines in the surfactant repel one another and theprotonated (neutral) co-surfactant does not prevent repulsion. However,as the HCl concentration decreases, both the protonated surfactant andthe protonated cosurfactant deprotonate. Therefore, the repulsion isdecreased and what repulsion remains is offset by the now anioniccosurfactant.

It should be understood that the viscous high-temperatureacid-degradable aqueous gels of the invention may contain components inaddition to water, surfactants and acids. Such additional componentsare, for example, conventional constituents that perform specificdesired functions such as chelating agents for the control ofmultivalent cations, corrosion inhibitors, corrosion inhibitor aids,fluid loss additives, freezing point depressants, clay control agents,and the like. The fluids and methods of the invention may also be usedwith weaker acids. That is, some wellbore treatments, such as matrixacidizing or acid fracturing, may use organic acids such as formic acidor acetic acid and the like, instead of or with stronger mineral acids.The viscous high-temperature acid-degradable aqueous gels of theinvention may be used to divert or to deliver such organic acidcontaining systems as mixtures of citric acid and boron trifluoride, ormixtures of organic acids and mineral acids such as HCl, HF, and boricacid.

The fluids and methods of the invention can be used at temperaturesabove which the surfactant decomposes in strong acid in a time that islong enough to complete the oilfield treatment but short enough topermit either the next step in a sequence of treatments or to beginflowback and production. For each surfactant/acid combination there is atemperature above which the gel will not remain sufficiently stable forsufficiently long for a given oilfield treatment to be performed. Foreach surfactant there is a temperature below which the decomposition istoo slow for the treatment to be practical because even very highconcentrations of mineral acid would not destroy the surfactant in ashort enough time. For example, BET-E-40 is stable to 15% HCl for over34 hours at 27° C.

The fluids and methods of the invention can be used with no added salts;that is the mineral acid alone would provide sufficient electrolyteconcentration to create and stabilize micelles and thus form a viscoushigh-temperature acid-degradable gel. For example, BET-E-40 provides asatisfactory gel in concentrations of HCl of less than about 12 percent. On the other hand, addition of a salt such as KCl, NaCl, CaCl₂,NH₄Cl, etc. is permissible. The fluid gelled in brine is not sensitiveto the brine concentration. Combinations of mineral acid and brine alsogive good viscous high-temperature acid-degradable gels.

The compositions of the present Invention are more environmentallyfriendly than compositions previously used, because injected fluidsreturned to the surface do not contain surfactants and the decompositionproducts do not include any materials that are not soluble in eitherwater or oil. Furthermore, the decomposition products (for example theerucic acid and the amine formed by the hydrolysis of the surfactant ofBET-E-40) are believed to be non-toxic to humans.

There are no restrictions on the order of addition of the componentswhen the aqueous viscous high-temperature acid-degradable gelled fluidsare being made up. The as-received surfactant mixture; water; mineralacid; alcohol, cosurfactant or chelating agent; and salt may be blendedin any order either in the field or at a separate location.Alternatively, any combination of some of the components can be premixedon site or at a separate location and then (an)other component(s) may beadded later. The fluids may be batch mixed or mixed on the fly. Standardmixing equipment and methods can be used; heating and special agitationare normally not necessary. Heating may be employed under extremely coldambient conditions. The exact amounts and specific surfactant or mixtureto be used will depend upon the viscosity desired, the temperature ofuse, the time desired before the viscosity has dropped below apredetermined value, and other similar factors. The concentrations ofthe active ingredients of the as-received surfactants in the finalfluids can vary between about 4% to about 15%, preferably about 5% toabout 10%, most preferably from about 6% to about 7.5%.

A wide variety of co-surfactants, organic salts, esters and alcohols canbe added in the formulation of the aqueous viscous high-temperatureacid-degradable gelled fluids in order to affect the viscosity and gelstability (as distinguished from the surfactant stability). For example,cationic surfactants such as erucyl methyl bis(2-hydroxyethyl) ammoniumchloride; amphoteric surfactants such as BET's themselves (for example,mixtures of BET's could be used); and anionic surfactants such as sodiumdodecyl benzene sulfonate. The amphoteric and cationic surfactants, ifused, are usually added in an amount of from about 0.5 to about 1.5volume percent, preferably about 0.5 volume percent. The anionicsurfactants, if used, are usually added in an amount of from about 0.1to about 0.5 weight percent. Other suitable anionics are, for example,sodium naphthalene sulfonate, sodium alpha olefin sulfonates andbranched or linear sodium dialkyl naphthalene sulfonates, such as sodiumdibutyl naphthalene sulfonate. Non-ionic surfactants should not be used.Various organic acids may be added, for example formic acid, aceticacid, propionic acid and glutaric acid. Such acids, if used, aretypically added in amounts of 20 volume percent or less, preferablyabout 2 to about 10 volume percent. Salts of fatty acids should not beused. Esters may also be added, for example dimethyl glutarate in anamount of up to about 6 volume percent. Alcohols may also be added;preferred alcohols are methanol, propylene glycol and ethylene glycol.Other alcohols that may be used are ethyl alcohol and propyl alcohol.Alcohols, if added, are added in an amount up to about 10 volumepercent, preferably in an amount of about 1 to about 6 volume percent.

As is usually the rule for acid treatments, the formulation willtypically comprise corrosion inhibitors, most preferably small amountsof acetic acid for example at a concentration of about 0.2% to about1.0%, and corrosion inhibitor aid, formic acid, for example at aconcentration of about 1% to about 2%, or corrosion inhibitors based onquaternary amines for example at a concentration of about 0.2% to about0.6%. A preferred corrosion inhibitor for the BET systems is aceticacid. Further agents may typically be added such as for instancenon-emulsifiers, iron reducing agents, and chelating agents. It shouldbe noted that, although no tests have been run, the formulation of thepresent invention is expected to be sensitive to iron, in particular toferric ions at a concentration of about 2000 ppm (parts per million) ormore. A preflush treatment with iron reducing agent and chelating agentis therefore recommended before the acid treatment. Though theformulation of the invention is compatible with small concentrations ofnon-emulsifying agents, to prevent emulsion and sludge, it is also agood practice to preflush the well with a mutual solvent, preferably lowmolecular weight esters, ether and alcohols, and more preferablyethylene glycol monobutyl ether. All other additives normally used inoilfield treatment fluids, such as, but not limited to, corrosioninhibitor aids, scale inhibitors, biocides, leak-off control agents,gravels, proppants, and others can also be included in the viscoushigh-temperature acid-degradable gelled aqueous fluids as needed,provided that none of them disrupts the structures giving rise to thesurfactant gels to the point where they no longer give stable highviscosity gels under the conditions at which they are needed.

Most importantly, unlike the VES Diverter described in U.S. Pat. No.5,979,557, the formulations of the present invention do not require oilor mutual solvent to flow back from the formation for the viscoushigh-temperature acid-degradable gel to break in the oil zone.Therefore, if there is some gel formed in the oil zone, the system canbe designed to break before flow back of mutual solvent and/or oilprogresses to the point where either of these materials is in contactwith the gel. The gel in the water zone may also be broken by dilutionif there is water flow, but although the likelihood of damage byVES-based diverters is generally very low, the compositions and methodsof the present invention guarantee that there will be no damage done tothe oil zone by emulsion or sludge formation. Breaking of the gel bydilution is a much less efficient process than destruction of thesurfactant by acid, so flow of formation water into the gel in the waterzone could delay breaking of the surfactant in the water zone by theacid (by diluting the acid) and thus prolong rather than reduce thediverting action. If no breaker is used, there is the potential forgreater oil production because gel may remain in the water zone, butthere is also the risk of decreased (or not increased) productionbecause of gel in the oil zone. With the acid, the potential increase inoil production might or might not be lower, but the risk of a failure toincrease oil production will be extremely low.

The system is adjusted so that the break time is greater than the pumptime. The break time will be a function of the choice of surfactant andits concentration; the temperature; the choice of acid and itsconcentration; the ionic concentration and the nature of both the anionsand cations, including ionized forms of other additives such aschelating agents, if present; and the nature and amount of alcoholpresent. However, for a given surfactant type, for example BET-O vs.BET-E, the stabilities are expected to be about the same (as a functionfor example of time, temperature and acid concentration) because theyhave the same electron withdrawing group in the degradable chemicalfunctionality. Surfactants having different electron withdrawing groupswill give different ranges of stabilities.

Variation in the amount of acid acting as surfactant breaker can be usedto control the time at which the viscous high-temperatureacid-degradable gel breaks at a given temperature. There will be acertain range of acid concentrations, for example from about 4% up toabout 7%, for BET-E, at which the gel strength will be about the same ata given temperature, but the time to break will decrease with increasingacid concentration. Above that acid concentration, the gel will breaktoo quickly to serve some functions. At an even higher acidconcentration, no gel will form. At too low an acid concentration, for agiven temperature, the gel will be stable for much longer than the timeit would take to perform a wellbore operation and then desire to beginhydrocarbon production. Although the data are not given here, at lowenough concentrations to be useful, these fluids are not expected toprovide viscosities above about 50 cP at 100 sec⁻¹ at temperatures ofabove about 150° C. for times long enough to perform oilfieldtreatments. For a given surfactant and surfactant concentration,depending upon what other components are present in the fluid, therewill be a temperature above which the surfactant will not be stable evenin the absence of a mineral acid added to decompose it

A viscous high-temperature acid-degradable gel containing 3% BET-E(active concentration)+7% HCl+1% methanol plus corrosion inhibitors willhave a lifetime of about 100 minutes at 66° C. (The lifetime beingdefined as the time before the viscosity of the gel falls below about 50cP at a shear rate of 170 sec⁻¹.) A similar gel in 4% HCl will have alifetime of more than 180 minutes at the same temperature. At 88° C., aviscous gel containing 3% BET-E+2% HCl+1% methanol plus corrosioninhibitors was shown to have a lifetime of about 240 minutes. A similargel in 4% HCl had a lifetime of only about 90 minutes at 88° C. Ofcourse, different systems having different surfactants and differentconcentrations of surfactant, acid and other additives will havedifferent lifetimes at different temperatures as can readily bedetermined by simple experimentation.

Other important uses for these fluids include fracturing (in the pad andin the fracture fluid), acid fracturing (in the pad or in stages thatalternate with acid stages), diversion, fluidloss pills, kill pills,temporary selective water shutoff, cementing and other oilfieldtreatment uses. Viscosities of at least about 30 to about 50 cP measuredat a shear rate of 100 sec⁻¹ are preferred for these uses. Although theuses are described in terms of producing wells for oil and/or gas, thefluids and methods may also be used for injection wells (such as forenhanced recovery or for storage or disposal) or for production wellsfor other fluids such as carbon dioxide or water.

EXAMPLE 1

Viscous high-temperature acid-degradable aqueous gels were made bymixing 7.5 volume per cent as received BET-E-40 (therefore 3 per centactive ingredient surfactant BET-E); varying amounts of concentrated (37per cent) HCl, 0.6 per cent of a high temperature corrosion inhibitormixture of formic acid, phenyl ketones and quaternary amines(hereinafter called corrosion inhibitor A); 2.0 per cent of 85 per centformic acid as additional corrosion inhibitor (hereinafter calledcorrosion inhibitor B); and 1 per cent methanol. These gels were thenheated to 88° C., held at that temperature for varying amounts of time,cooled to room temperature, and observed. The results are shown in Table1.

TABLE 1 Time (min) 7% HCl 4% HCl 2% HCl 15 Viscous Viscous Viscous 30Viscous Viscous Viscous 45 Less viscous Viscous Viscous 60 Water-likeViscous Viscous 90 Phase separation Less viscous Viscous 120 Lessviscous Viscous 180 Phase separation Viscous

The table shows that the fluid becomes more unstable with increasing HClconcentration.

The viscosities of the cooled fluids of column 2 of Table 1 weremeasured with a Fann 35 viscometer. The results are shown in Table 2 fortwo different shear rates at room temperature.

TABLE 2 Time (min) 170 sec⁻¹ 510 sec⁻¹ 0 285 115 15 288 115 30 255 11045 240 105 90 84 70 120 75 35

The sample of the same fluid was heated to 66° C., held at thattemperature for varying amounts of time, cooled to room temperature, andobserved. The viscosities of the cooled fluids were measured with a Fann35 viscometer. The results are shown in Table 3 for two different shearrates at room temperature.

TABLE 3 Time (min) 170 sec⁻¹ 510 sec⁻¹ 15 294 127 30 303 125 45 297 12860 315 130 90 303 128 120 294 123 180 225 122

These data show that this fluid, containing 4% concentrated HCl, is verystable at this temperature, even at relatively high shear rates.

EXAMPLE 2

The following fluids were prepared by mixing 7.5% by volume of BET-E-40with 5–10% by weight of either potassium chloride or ammonium chloride.

Fluid 1: 7.5 volume per cent as received BET-E-40 and 5 per centpotassium chloride; pH adjusted to 9.58 with sodium hydroxide.

Fluid 2: 7.5 volume per cent as received BET-E-40 and 5 per centpotassium chloride; pH adjusted to 6.52 with sodium hydroxide.

Fluid 3: 7.5 volume per cent as received BET-E-40 and 10 per centpotassium chloride; pH adjusted to 6.79 with sodium hydroxide.

Fluid 4: 7.5 volume per cent as received BET-E-40 and 10 per centpotassium chloride; pH adjusted to 7.81 with sodium hydroxide.

Fluid 5: 7.5 volume per cent as received BET-E-40 and 5 per centammonium chloride; pH adjusted to 7.40 with sodium hydroxide.

Fluid 6: 7.5 volume per cent as received BET-E-40 and 7 per centammonium chloride; pH adjusted to 7.78 with sodium hydroxide.

The viscosities of these materials were measured in a Fann 50 viscometerwhile they were being heated to about 150° C.; the results are shown inTables 4, 5 and 6. The temperatures listed are plus or minus about 2° C.These data show the behavior of fluids in the absence of added mineralacids.

TABLE 4 Fluid 1 Fluid 2 ° C. 40 sec⁻¹ 100 sec⁻¹ 170 sec⁻¹ 40 sec⁻¹ 100sec⁻¹ 170 sec⁻¹ 25 336 213 164 373 239 185 37 547 290 201 523 271 185 53560 278 185 457 237 162 67 269 166 126 231 125 88 80 308 135 83 310 13786 94 380 156 93 380 156 94 108 444 198 124 444 199 125 121 330 193 142276 185 147 135 178 98 70 111 80 66 149 106 57 39 55 31 22

TABLE 5 Fluid 3 Fluid 4 ° C. 40 sec⁻¹ 100 sec⁻¹ 170 sec⁻¹ 40 sec⁻¹ 100sec⁻¹ 170 sec⁻¹ 25 361 239 188 324 219 175 37 527 280 194 406 250 189 53433 236 166 432 224 153 67 196 114 84 180 90 61 80 271 121 76 241 105 6594 322 133 80 286 118 70 108 412 178 109 355 155 96 121 309 193 147 252162 126 135 148 105 86 124 87 71 149 78 48 36 68 40 30

TABLE 6 Fluid 5 Fluid 6 ° C. 40 sec⁻¹ 100 sec⁻¹ 170 sec⁻¹ 40 sec⁻¹ 100sec⁻¹ 170 sec⁻¹ 25 324 174 122 279 174 132 37 423 222 153 397 205 140 53238 153 118 164 124 106 67 255 118 76 221 101 64 80 279 119 73 235 99 6094 344 144 87 298 123 74 108 376 197 136 273 174 134 121 199 142 117 15798 74 135 112 73 56 85 42 28 149 69 36 25 41 19 12

It can be seen that all these fluids behave very similarly. They eachhave one maximal viscosity at about 37° C. and another at about 108° C.,above which the viscosities gradually decrease. They are quireinsensitive to the nature or the concentration of the added salt. Allare shear thinning throughout the temperature and shear rate rangesexplored, and all show appreciable viscosity throughout those ranges.

The following fluid was prepared by mixing:

-   Fluid 7: 7.5 volume per cent as received BET-E-40, 15 per cent    concentrated (37 per cent) HCl, 10 per cent methanol, 0.6 per cent    of corrosion inhibitor A, and 2 per cent of corrosion inhibitor B.    This fluid was then aged at 54° C. for a specified time. The fluid    was then cooled, and a sufficient amount of CaCO₃ was added to react    with all the acid. The pH of the fluid after this reaction with the    acid was from about 4.2 to about 4.6. The viscosity of the fluid    samples was then measured in a Fann 50 viscometer while they were    being heated to about 150° C.; the results are shown in Tables 7 and    8.

TABLE 7 Aged for: 1 hour 2.5 hours ° C. 40 sec⁻¹ 100 sec⁻¹ 170 sec⁻¹ 40sec⁻¹ 100 sec⁻¹ 170 sec⁻¹ 25 757 494 386 849 530 403 37 797 403 271 929449 294 53 1203 570 369 1183 550 353 67 1022 684 542 807 531 417 80 643282 175 655 278 169 94 736 344 221 727 344 223 108 380 286 243 369 280239 121 167 141 129 158 126 111 135 80 58 48 95 63 50 149 51 32 24 68 3726

TABLE 8 Aged for: 8 hours 24 hours ° C. 40 sec⁻¹ 100 sec⁻¹ 170 sec⁻¹ 40sec⁻¹ 100 sec⁻¹ 170 sec⁻¹ 25 724 429 317 574 322 230 37 963 502 344 274193 158 53 517 307 227 218 93 57 67 514 224 139 191 106 75 80 563 235141 102 59 43 94 449 276 208 70 30 18 108 155 127 113 62 25 15 121 10466 51 104 66 51 135 59 28 18 59 28 18 149 49 20 12

The data in Tables 7 and 8 show that this fluid is degraded only slowlyeven in 15 per cent HCl at 54° C. Even after 8 hours exposure, thisfluid still had a viscosity of over 50 cP at 100 sec⁻¹ at 121° C. andhad a viscosity of 20 cP at 100 sec⁻¹ at 149° C.

EXAMPLE 3

The fluid of Example 1 containing 7 per cent HCl was heated at 88° C.and at 66° C., held at those temperatures for varying amounts of time,cooled to room temperature, and observed. The viscosities of the cooledfluids were measured with a Fann 35 viscometer. The results are shown inTable 9 for each aging temperature at a shear rate of 170 sec⁻¹ at roomtemperature.

TABLE 9 Time (Minutes) Aged at 88° C. Aged at 66° C. 15 321 321 30 318309 45 312 336 60 165 336 90 42 294 120 21 99 180 6 60

The data in Examples 1 through 3 clearly show that these fluids can bestable in strong mineral acids at high temperatures for long enough toperform many oilfield operations and that they then degrade. The higherthe mineral acid concentration, or the higher the temperature, the morerapidly the surfactant decomposes and the shorter the time before thefluid decomposes and any undesired effects are eliminated. Equipment wasnot available to age these highly acidic fluids at temperatures aboveabout 88° C. or to measure their viscosities above room temperature.

EXAMPLE 4

The data in FIGS. 1 through 4 show how the viscosity of one viscoushigh-temperature acid-degradable aqueous gel varies with time,temperature and acid concentration. The gel was made with 7.5%as-received BET-E-40. FIG. 1 shows the initial viscosity of a gel madewith 5% KCl and 2% HCl as a function of temperature; this gel is stableover a very broad temperature range, and would be useful at temperaturesup to at least 150° C. The viscosity varies a little over thetemperature range studied, which is not unusual for such systems, but isrelatively constant. FIG. 2 shows the initial viscosity at ambienttemperature of the same system (except without the KCl) over a verybroad range of HCl concentrations. The variations are typical of suchsystems although the exact HCl concentrations at which the effects areobserved would vary with different surfactants. This system gels in theabsence of any added salt. As the HCl concentration is increased, theinitial viscosity also increases up to a certain HCl concentration, inthis case about 7. This is also typical of such systems. At increasinglyhigher HCl concentrations, the initial viscosity begins to decrease butis still above about 50 cP up to a fairly high HCl concentration, inthis case about 17%. At even higher concentrations the viscosity is verylow. FIG. 3 shows the time at 88° C. for the viscosity of four of thegels of FIG. 2, having different acid concentrations, to fall belowabout 50 cP, and FIG. 4 shows the decrease in viscosity as a function oftime for the first three gels of FIG. 3. These data show how thestability and rate of degradation of such gels can be determined andcontrolled. At low acid concentrations the systems are strong stablegels; at intermediate acid concentrations the systems form more viscousstable gels that degrade at rates that increase with increasing acidconcentration. At high acid concentrations, this particular system doesnot form a viscous gel.

1. A method of diverting fluid, injected in a well treatment of astratified subterranean formation comprising at least one problematiczone and at least one non-problematic zone, into said problematic zone,comprising injecting a diverting fluid comprising an aqueous viscousfluid comprising water, a gelling amount of a viscoelastic surfactantcomprising an amidoamine oxide, and a mineral acid at a concentration offrom about 2% to about 16%, wherein the diverting fluid initiallypreferentially enters the non-problematic zone and the fluid gels as theacid reacts with the formation, thereby diverting subsequently injectedfluid into said problematic zone.
 2. The method of claim 1 wherein theamidoamine oxide surfactant has the following structure:

wherein R₁ is a hydrocarbyl group that may be branched or straightchained, aromatic, aliphatic or olefinic and has from about 14 to about26 carbon atoms and may contain an amine; R₂ is hydrogen or an alkylgroup having from 1 to about 4 carbon atoms; R₃ is a hydrocarbyl grouphaving from 1 to about 10 carbon atoms; and Y is an amine oxide.
 3. Themethod of claim 1 wherein the diverting fluid further comprises acosurfactant.
 4. The method of claim 1 wherein the diverting fluidfurther comprises an alcohol.
 5. The method of claim 1 wherein thediverting fluid further comprises a chelating agent.
 6. The method ofclaim 1 wherein the diverting fluid further comprises an iron controlagent.
 7. The method of claim 1 wherein the diverting fluid furthercomprises a corrosion inhibitor.
 8. The method of claim 1 wherein thediverting fluid further comprises a glycol.
 9. The method of claim 1wherein the well treatment is acid fracturing.
 10. The method of claim 1wherein the well treatment is matrix acidizing.
 11. The method of claim1 wherein the well treatment is matrix dissolution with a fluidcomprising a chelating agent.
 12. The method of claim 1 wherein themethod further comprises injecting a mutual solvent prior to injectingthe diverting fluid.
 13. The method of claim 12 wherein the mutualsolvent is selected from the group consisting of low molecular weightesters, alcohols, and ethers.
 14. The method of claim 13 wherein themutual solvent is ethylene glycol monobutyl ether.
 15. The method ofclaim 1 wherein the acid is selected from the group consisting ofhydrochloric acid, hydrofluoric acid, acetic acid, formic acid, boricacid, propionic acid, glutaric acid and mixtures thereof.
 16. A methodof diverting fluid, injected in a well treatment of a stratifiedsubterranean formation comprising at least a zone of higher permeabilityand a zone of lower permeability, comprising injecting into saidformation a gelled diverting fluid comprising an aqueous viscous fluidcomprising water, a gelling amount of a viscoelastic surfactantcomprising an amidoamine oxide, and an acid, and a member selected froma corrosion inhibitor and ethylene glycol monobutyl ether, wherein saidgelled fluid at least partially blocks flow of fluid into said zone ofhigher permeability.
 17. A method of diverting fluid, injected in a welltreatment of a stratified subterranean formation comprising at least oneproblematic zone and at least one non-problematic zone, into saidproblematic zone, comprising injecting a diverting fluid comprising anaqueous viscous fluid comprising water, a gelling amount of aviscoelastic surfactain comprising an amidoamine oxide having thefollowing structure:

wherein R₁, is a hydrocarbyl group that may be branched or straightchained, aromatic, aliphatic or olefinic and has from about 14 to about26 carbon atoms and may contain an amine; R₂ is an alkyl group havingfrom 1 to about 4 carbon atoms; R₃ is a hydrocarbyl group having from 1to about 10 carbon atoms; and Y is an amine oxide, and an acid, whereinthe diverting fluid initially preferentially enters the non-problematiczone and the fluid gala as the acid reacts with the formation, therebydiverting subsequently injected fluid into said problematic zone.